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218-114
Carlisle, Samantha J (DOA) From: Davies, Stephen F (DOA) Sent: Monday, February 11, 2019 3:41 PM To: Carlisle, Samantha J (DOA) Cc: Boyer, David L (DOA) Subject: Withdraw the Permits to Drill for KRU 2G-061-1-01 (PTD 218-113), L1-02 (PTD 218-114), and L1-03 (PTD 218-115) Attachments: 2G-06A_wp06 MD - NAD27.txt; 2G-06AL1_wp05 MD - NAD27.txt; 2G-06AL2_wp03 MD - NAD27.txt; 2G-06AL2-01_wp03 MD - NAD27.txt Sa m, Please place a copy of the email below in the following well history files: KRU 2G-06L1-01 (PTD 218-113), L1-02 (PTD 218-114), and L1-03 (PTD 218-115). Thanks, Steve D CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Herring, Keith E <Keith.E.Herring@conocophillips.com> Sent: Monday, February 11, 2019 3:26 PM To: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL]Survey Digital Files for KRU 2G-06A, KRU 2G-06AL1, KRU 2G-06AL2, and KRU 2G-06AL2-01 Steve, Please see attached. As per our conversation please withdraw the Permit to Drill applications for the KRU 2G-06L1-01, L1-02, and L1-03 that were issued during 2018. Thanks, Keith Herring CTD Engineer 907.263.4321 (Office) 907.570.2410 (Mobile) 700 G Street, ATO — 664 Keith. E.Hening(n;conocophillips.com ConocoPhill 5 Alaska From: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Sent: Monday, February 11, 2019 3:06 PM To: Herring, Keith E <Keith.E.Herring@,-onocophillips.com> Subject: [EXTERNAL]Survey Digital Files for KRU 2G-06A, KRU 2G-06AL1, KRU 2G-06AL2, and KRU 2G-06AL2-01 Keith, Could CPAI please provide digital files of the proposed directional surveys for KRU 2G-06A, KRU 2G-06AL1, KRU 2G- 06AL2, and KRU 2G-06AL2-01? Having these files will speed review of the Permit to Drill applications for these wellbores. Excel spreadsheet or ASCII table formats are acceptable. I only need MD, Azimuth and Inclination information. Does CPAI wish to withdraw the Permit to Drill applications for KRU 2G-06L1, L1-01, L1-02 and L1-03 that were issued during 2018? Thank you for your help, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) 907-793-1224 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Herring, Keith E <Keith.E.Herring(@conocophillips.com> Sent: Friday, September 21, 2018 9:16 AM To: Boyer, David L (DOA) <david. boyer2@alaska.gov> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov>; Long, William R <William.R.Long@conocophillips.com> Subject: RE: [EXTERNAL]Survey Digital Files for KRU 2G-06L1, 1-1-01, L1-02 and L1-03 Dave, Please see attached. Thanks, Keith Herring CTD Engineer 907.263.4321 (Office) 907.570.2410 (Mobile) 700 G Street, ATO — 664 Keith.E.Herring@conocophillips.com ConocoPhillips Aaska From: Boyer, David L (DOA) <david.boyer2@alaska.gov> Sent: Friday, September 21, 2018 8:46 AM To: Herring, Keith E <Keith.E.Herring @conocophill ips.com> Cc: Davies, Stephen F (DOA) <steve.davies@alask�ov> Subject: [EXTERNAL]Survey Digital Files for KRU 2G-06L1, 1-1-01, L1-02 and L1-03 Hi Keith, Permit to Drill Applications for the 4 KRU 2G-06 laterals on 09/18. Steve and I are reviewing them and see that the first lateral is scheduled for 10/01/18. If you can e-mail me digital surveys (Excel or ASCII text files) for the 4 laterals, it really speeds up the data entry into our Geographics database. We only load the MD, inclination, and azimuth columns but if it is easier to send the Baker Hughes files, we can extract what we need to plot the well on our maps. Thank you, Dave Boyer Senior Geologist AOGCC THE STATE 'ALASKA GOVERNOR BILL WALKER James Ohlinger Staff CTD Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G-06L1-02 ConocoPhillips Alaska, Inc. Permit to Drill Number: 218-114 Surface Location: 547' FSL, 236' FWL, SEC. 32, T11N, R9E, UM Bottomhole Location: 2536' FNL, 1065' FEL, SEC. 32, Tl 1N, R9E, UM 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Dear Mr. Ohlinger: Enclosed is the approved application for the permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 184-082, API No. 50-029-21121-00- 00. Production should continue to be reported as a function of the original API number stated above. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Hollis S. French Chair DATED this day of October, 2018. t STATE OF ALASKA AL—K<A OIL AND GAS CONSERVATION COMMIboION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: Drill ❑ Lateral ❑✓ Redrill ❑ Reentry ❑ 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Stratigraphic Test ❑ Development - Oil ❑✓ Service - Winj ❑ Single Zone Q Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ 1 c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: Blanket ❑✓ Single Well ❑ Bond No. 5952180 - 11. Well Name and Number: KRU 2G-061-1-02 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 9900, TVD: 5898' 12. Field/Pool(s): Kuparuk River Field / Kuparuk River Oil Pool . 4a. Location of Well (Governmental Section): Surface: 547' FSL, 236' FWL, Sec 32, T11 N, R9E, UM Top of Productive Horizon: 1312' FNL, 1241' FEL, Sec 32, T11N, R9E, UM Total Depth: 2536' FNL, 1065' FEL, Sec 32, T11 N, R9E, UM 7. Property Designation: ADL 25656 8. DNR Approval Number: LONS 82-180 13. Approximate Spud Date: 10/1/2018 9. Acres in Propertv: 2491 14. Distance to Nearest Propertv: 22200' - 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 508930 y- 5944135 Zone- 4 10, KB Elevation above MSL (ft): 140' ° GL / BF Elevation above MSL (ft): 104' 15. Distance to Nearest Well Open to Same Pool: 1285" 2G-08 16. Deviated wells: Kickoff depth: 8300' feet Maximum Hole Angle: 98 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 4,908 Surface: 4,320 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 3" 2-3/8" 4.7# L-80 ST-L 1500' 8400' 5914' 9900, 5898' Slotted 19, PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 8485' Total Depth TVD (ft): 6253' Plugs (measured): N/A Effect. Depth MD (ft): 8368' Effect. Depth TVD (ft): 6158' Junk (measured): 8158' Casing Length Size Cement Volume MD TVD Conductor/Structural 72' 16" 202 sx Cold Set II 110, 110, Surface 3097' 9-5/8" 1035 sx PF E, 250 sx PF C 3134' 2774' Production 8413' 7" 575 sx Class G, 250 sx PF C 8449' 6224' Perforation Depth MD (ft): 8188' - 8198' 8216' - 8246' Perforation Depth TVD (ft): 6013' - 6021' 6035' - 6060' Hydraulic Fracture planned? Yes❑ No ❑� BOP Sketch 20. Attachments: Property Plat ❑ Divertter Sketch Drilling Program Tim e Seabed Report B Dri I ngeFluid Progrv. Depth am e 20 AAC 25 050 regot Shallowdui ements e 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Keith Herring Authorized Name: James Ohlinger Contact Email: Keith. E.Herrinco .com Authorized Title: Staff CTD Engineer o Contact Phone: 907-263-4321 Authorized Signature: Date: fl /p 1001 Commission Use Only Permit to Drill Number: a I — ( It% API Number: 50-029 ^ a 1 Z1 -6A 1 QC) Permit Approval Date: � See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes ❑ No[r Mud log req'd: Yes❑ No[T Other: Q©P t�—,5 7� to G��S i $-OIi v1 vl ct r— 12 /---e—Yfv� 1-r �lv�t 7, �2 EGG. me5asures: Yes [� No❑ Directional svy req'd: Yes [9No❑ Z 7-o _20 A,q C � 5. /$ r-6.)Spacing exceptiJh req'd: Yes ❑ No Ew�' Inclination -only svy req'd: Yes ❑ No [�r 75 '1"D C�/�O t ✓ fh � Post initial injection MIT req'd: Yes ❑ No d ,� y p&,h -t �l��ry 7'_/1Z!- APPROVED BY Approved by: �@ s COMMISSIONER THE COMMISSION Date: V77 %0/.%//f� Submit Form and Form 10-401 Revised 5/2017 Thfs`(drfFlit is valid for 20ofslr6tf NALroval per 20 AAC 25.005(g) Attachments n Duplicate Conocophillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 10, 2018 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the KRU 2G-06 (PTD# 184-082) using the coiled tubing drilling rig, Nabors CDR3-AC. CTD operations are scheduled to begin in October 2018. The objective will be to drill four laterals, KRU 2G- 061-1, 2G-061-1-01, 2G-061_1-02, and 2G-061_1-03, targeting the Kuparuk A -sand interval. To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC 25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of being limited to 500' from the original point. Attached to this application are the following documents: — Permit to Drill Application Forms (10-401) for 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-061-1-03 — Detailed Summary of Operations — Directional Plans for 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-06L1-03 — Current wellbore schematic — Proposed CTD schematic If you have any questions or require additional information, please contact me at 907-263-4321. Sincerely, Keith Herring Coiled Tubing Drilling Engineer ConocoPhillips Alaska Kuparuk CTD Laterals 2G-061-1, 2G-0611-1-01, 2G-0611-1-02, and 2G-061-1-03 Application for Permit to Drill Document 1. Well Name and Classification........................................................................................................ 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005 c 2......................................................................... 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2 5. Procedure for Conducting Formation Integrity tests................................................................... 2 (Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2 6. Casing and Cementing Program.................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(6))..................................................................................................................................................3 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AAC 25.005(c)(7))................................--.-...........................................................................................................3 8. Drilling Fluids Program.................................................................................................................. 3 (Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4 11. Seabed Condition Analysis............................................................................................................4 (Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4 13. Proposed Drilling Program............................................................................................................. 4 (Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4 Summaryof Operations...................................................................................................................................................4 LinerRunning...................................................................................................................................................................6 14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6 15. Directional Plans for Intentionally Deviated Wells....................................................................... 7 (Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-061-1-03 laterals................................7 Attachment 2: Current Well Schematic for 2G-06...........................................................................................................7 Attachment 3: Proposed Well Schematic for 2G-06L1, 2G-061-1-01, 2G-061-1-02, and 2G-06L1-03 laterals.................7 Page 1 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-061-1-03. All laterals will be classified as "Development -Oil' wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface and subsurface coordinates of each of the laterals. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC. BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 5,000 psi. Using the maximum formation pressure in the area of 4,908 psi in 213-05 (i.e. 15.5 ppg EMW), the maximum potential surface pressure in 2G-06, assuming a gas gradient of 0.1 psi/ft, would be 4,320 psi. See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2,500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The formation pressure in KRU 2G-06 was measured to be 3,897 psi (12.6 ppg EMW) on 7/15/2018. The v maximum downhole pressure in the 2G-06 vicinity is the 213-05 at 4,908 psi or 15.5 ppg EMW. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of encountering gas while drilling the 2G-06 laterals. If significant gas is detected in the returns the contaminated mud can be diverted to a storage tank away from the rig. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) . The major expected risk of hole problems in the 2G-06 laterals will be shale instability across faults. Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) The 2G-06 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity test is not required. Page 2 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-061_1-03 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) New Completion Details Lateral Name Liner Top Liner Btm Liner Top Liner Btm Liner Details MD MD TVDSS TVDSS 2G-061_1 8,400' 9,750' 5,912' 5,882' 2'/", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-061_1-01 8,300' 9,750' 5,913' 5,859' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-061_1-02 8,400' 9,900, 5,914' 5,898' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 2G-061_1-03 8,006' 9,900, 5,730' 5,873' 23/", 4.7#, L-80, ST-L slotted liner; deployment sleeve on to Existing Casing/Liner Information Category OD Weigh t f Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded Surface 110, Surface 110, 1640 670 Surface 9-5/8" 36 J-55 BTC Surface 3134' Surface 2774' 3520 2020 Production 7" 26 J-55 BTC Surface 8449' Surface 6224' 4980 4320 Tubing 3-1/2" 9.3 L-80 EUE 8rd MOD Surface 8044' Surface 5899' 10,160 10,540 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System A diagram of the Nabors CDR3-AC mud system is on file with the Commission. Description of Drilling Fluid System — Window milling operations: Water based Power-Vis milling fluid (8.6 ppg) — Drilling operations: Water based Power -Pro drilling mud (8.6 ppg). This mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. — Completion operations: BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.8 ppg potassium formate completion fluid in order to provide formation over -balance and maintain wellbore stability while running completions. If higher formation pressures are encountered the completion brine will be weighted up with potassium formate. Page 3 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000-psi rated coiled tubing pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout Prevention Equipment Information". In the 2G-06 laterals we will target a constant BHP of 12.6 EMW at the window. The constant BHP target will be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 2G-06 Window (8,134' MD, 5,970' TVD) Usinq MPD Pumps On 1.8 b m Pumps Off Formation Pressure 12.6 3897 psi 3897 psi Mud Hydrostatic 8.6 2669 psi 2669 psi Annular friction i.e. ECD, 0.080 si/ft 650 psi 0 psi Mud + ECD Combined no chokepressure) 3319 psi underbalanced --578psi) 2669 psi underbalanced —1228 si Target BHP at Window 12.6 3911 psi 3911 psi Choke Pressure Required to Maintain Target BHP 592 psi 1242 psi 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis , (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is for a land based well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background KRU well 2G-06 is a Kuparuk producer equipped with 3-1/2" tubing and 7" production casing. The CTD sidetrack will utilize laterals to target the Kuparuk A -sands to the north and south of the existing 2G-06 wellbore. The laterals will reclaim resource from the long term shut in rock producer 2G-06 and provide additional offtake in a high-pressure area. Page 4 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03 CDR3-AC will set a mechanical whipstock (High Expansion Wedge) inside the 7" casing at the planned kick off point of 8,134' MD. The 2G-06L1 lateral will exit through the 7" at 8,134'MD and TD at 9,750' MD, targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8,400' MD with an aluminum billet for kicking off the 2G-06L1-01 lateral. The 2G-06L1-01 lateral will drill to a TD of 9,750' MD targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8,300' MD with an aluminum billet for kicking off the 2G-06L 1-02 lateral. The 2G-06L1-02 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be completed with 2-3/8" slotted liner from TD up to 8,400' MD with an aluminum billet for kicking off the 2G-06L 1-03 lateral. The 2G-06L1-03 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be completed with 2-3/8" slotted liner from TD up into the 3-1/2" tubing at 8,006' MD with a deployment sleeve. Pre-CTD Work 1. RU Service Coil: Conduct fill cleanout. 2. RU Slickline: Obtain SBHP and conduct dummy whipstock drift. 3. Prep site for Nabors CDR3-AC. Rig Work 1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 2G-06L 1 Lateral (A4 sand - North) a. Set top of high expansion wedge at 8,134' MD. b. Mill 2.80" window at 8,134' MD. c. Drill 3" bi-center lateral to TD of 9,750' MD. d. Run 2%" slotted liner with an aluminum billet from TD up to 8,400' MD. 3. 2G-06L 1-01 Lateral (A4 sand -North) a. Kick off of the aluminum billet at 8,400' MD. b. Drill 3" bi-center lateral to TD of 9,750' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 8,300' MD. 4. 2G-06L 1-02 Lateral (A4 sand -South) a. Kickoff of the aluminum billet at 8,300' MD. b. Drill 3" bi-center lateral to TD of 9,900' MD. c. Run 2%" slotted liner with aluminum billet from TD up to 8,400' MD. 5. 2G-06L1-03 Lateral (A4 sand - South) a. Kick off of the aluminum billet at 8,400' MD. b. Drill 3" bi-center lateral to TD of 9,900' MD. c. Run 2%" slotted liner with deployment sleeve from TD up to 8,006' MD. 6. Obtain SBHP, freeze protect, ND BOPE, and RDMO Nabors CDR3-AC. Post -Rig Work 1. Return to production. Page 5 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-0611-1-01, 2G-0611-1-02, and 2G-0611-1-03 Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure using a system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slick -line. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — 2G-06 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling Fluids Program") prior to running liner. — While running 23/" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. • All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. • Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. • All wastes and waste fluids hauled from the pad must be properly documented and manifested. • Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). Page 6 of 7 September 10, 2018 PTD Application: 2G-06L1, 2G-0611-1-01, 2G-0611-1-02, and 2G-06L1-03 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) - The Applicant is the only affected owner. - Please see Attachment 1: Directional Plans - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. - MWD directional, resistivity, and gamma ray will be run over the entire open hole section. - Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 2G-06L1 23,075' 2G-06L1-01 23,075' 2G-06L1-02 - 22,200' 2G-06L1-03 22,200' - Distance to Nearest Well within Pool Lateral Name Distance Well 2G-06L1 525' 2F-20 2G-06L1-01 525' 2F-20 2G-06L1-02 1285' 2G-08 2G-061-1-03 1285' 2G-08 16. Attachments Attachment 1: Directional Plans for 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03laterals. Attachment 2: Current Well Schematic for 2G-06. Attachment 3: Proposed Well Schematic for 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03 laterals. Page 7 of 7 September 10, 2018 cn 17 I ConocoPhilli s p _ConocoPhillips Export Company Kuparuk River Unit Kuparuk 2G Pad 2G-06 2G-06L1-02 Plan: 2G-06L1-02_wp03 Standard Planning Report 21 August, 2018 BA ER UGHES a GE company ConocoPhillips Database: EDT 14 Alaska Production Company: _ConocoPhillips Export Company Project: Kuparuk River Unit Site: Kuparuk 2G Pad Well: 2G-06 Wellbore: 2G-061-1-02 Design: 2G-06L 1-02_wp03 ConocoPhillips BA- j{ER Planning Report UGHES a GE company Local Coordinate Reference: Well 2G-06 TVD Reference: Mean Sea Level MD Reference: 2G-06 @ 140.00usft (2G-06) ` North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Kuparuk 2G Pad I Site Position: Northing: 5,944,015A2usft Latitude: 70° 15' 29.734 N From: Map Easting: 508,649.96 usft Longitude: 149' 55' 48.314 W Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.07 ° Well 2G-06 i i j Well Position +N/-S 0.00 usft Northing: 5,944,135.21 usft ° Latitude: 70° 15' 30.911 N +E/-W 0.00 usft Easting: 508,929.90 usft Longitude: 149° 55' 40.165 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 2G-061-1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength i (°) (°) (nT) BGG M2018 12/1 /2018 16.75 80.81 57,424 Design 2G-06L1-02_wp03 i Audit Notes: j Version: Phase: PLAN Tie On Depth: 8,300.00 Vertical Section: Depth From (TVD) +N/S +E/-W Direction (usft) (usft) (usft) {°) 0.00 0.00 0.00 180.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/S +E/-W Rate Rate Rate TFO (usft) (°) (°) (usft) (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) Target 8,300.00 82.31 49.07 5,913.06 3,422.25 3,790.98 0.00 0.00 0.00 0.00 8,400.00 96.57 73.23 5,914.05 3,470.00 3,877.71 28.00 14.26 24.16 60.00 8,800.00 87.54 185.10 5.892.33 3,255.07 4,139.34 28.00 -2.26 27.97 90.00 9.000.00 84.26 198.74 5,906.70 3,060.37 4,098.28 7.00 -1.64 6.82 104.00 9,150.00 90.32 207.33 5,913.80 2,922.69 4,039.71 7.00 4.04 5.72 55.00 9,350.00 98.49 195A2 5,898.40 2,737.82 3,966.31 7.00 4.08 -5.71 306.00 9,550.00 89.39 185.23 5,884.63 2,542.15 3,929.89 7.00 -4.55 -5.34 230.00 9,900.00 86.14 160.93 5,898.47 2,197.61 3,971.61 7.00 -0.93 -6.94 262.00 812112018 1:56:46PM Page 2 COMPASS 5000.14 Build 85 ConocoPhillips BA ER ConocoPhillips Planning Report BAT a GE company Database: Company: Project: Site: Well: Wellbore: Design: EDT 14 Alaska Production _ConocoPhillips Export Company Kuparuk River Unit Kuparuk 2G Pad 2G-06 2G-060-02 2G-061-1-02_wp03 Local Co-ordinate Reference: Well 2G-06 TVD Reference: Mean Sea Level MD Reference: 2G-06 @ 140.00usft (2G-06) North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +Nl-S +E/-W Section Rate Azimuth Northing Easting (usft) (1) (°) (usft) (usft) (usft) (usft) (°1100usft) (°) (usft) (usft) 8,300.00 82.31 49.07 5,913.06 3,422.25 3,790.98 -3,422.25 0.00 0.00 5,947,561.61 512,716.44 TIP/KOP 8,400.00 96.57 73.23 5,914,05 3,470.00 3,877.71 -3,470.00 28.00 60.00 5,947,609.46 512,803.10 Start 28 dls 8,500.00 95.80 101.39 5,903.05 3,474.61 3,976.00 -3,474.61 28.00 90.00 5,947,614.18 512,901.38 8,600.00 93.67 129.40 5,894.63 3,432.27 4,065.10 -3,432.27 28.00 93.10 5,947,571.95 512,990.52 8,700.00 90.69 157.27 5,890.75 3,352.90 4,124.15 -3,352.90 28.00 95.46 5,947,492.66 513,049.66 8,800.00 87.54 185.10 5,892.33 3,255.07 4,139.34 -3,255.07 28.00 96.54 5,947,394.86 513,064.96 End 28 dls, Start 7 dls 8,900.00 85.87 191.91 5,898.08 3,156.40 4,124.59 -3,156.40 7.00 104.00 5,947,296.18 513,050.33 9,000.00 84.26 198.74 5,906.70 3,060.37 4,098.28 -3,060.37 7.00 103.61 5,947,200.13 513,024.14 4 9,100.00 88.29 204.48 5,913.20 2,967.66 4,061.55 -2,967.66 7.00 55,00 5,947,107.38 512,987.52 9,150.00 90.32 207.33 5,913.80 2,922.69 4,039.71 -2,922.69 7.00 54.63 5,947,062.39 512,965.74 5 9,200.00 92.38 204.50 5,912.62 2,877.74 4,017.87 -2,877.74 7.00 -54.00 5,947,017.42 512,943.95 9,300.00 96.47 198.80 5,904.91 2,785.13 3,961.10 -2,785.13 7.00 -54.07 5,946,924.78 512,907.30 9,350.00 98.49 195.92 5,898.40 2,737.82 3,966.31 -2,737.82 7.00 -54.51 5,946.877.46 512,892.57 6 9,400.00 96.23 193.22 5,892.00 2,689.83 3,953.85 -2,689.83 7.00 -130.00 5,946,829.46 512,880.16 9,500.00 91.68 187.89 5,885.10 2,591.82 3,935.60 -2,591.82 7.00 -130.35 5,946,731.43 512,862.03 9,550.00 89.39 185.23 5,884.63 2,542.15 3,929.89 -2,542.15 7.00 -130.71 5,946,681.77 512,856.38 7 9.600.00 88.91 181.77 5,885.37 2,492.26 3,926.83 -2,492.26 7.00 -98.00 5,946,631.87 512,853.38 9,700.00 87.95 174.83 5,888.11 2,392.40 3,929.80 -2,392.40 7.00 -97.95 5,946,532.03 512,856.46 9.800.00 87.02 167.89 5,892.50 2,293.70 3,944,79 -2,293.70 7.00 -97.76 5,946,433.35 512,871.58 9,900.00 86.14 160.93 5,898.47 " 2,197.61 3,971.61 -2,197.61 7.00 -97.45 5,946,337.30 512,898.50 Planned TD at 9900.00 'asing Points - Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,900.00 5,898.47 2 3/8" 2.375 3.000 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 8,300.00 5,913.06 3,422.25 3,790.98 TIP/KOP 8,400.00 5,914.05 3,470.00 3,877.71 Start 28 dis 8,800.00 5,892.33 3,255.07 4,139.34 End 28 dis, Start 7 dls 9,000.00 5,906.70 3,060.37 4,098.28 4 9,150.00 5,913.80 2.922.69 4,039.71 5 9,350.00 5,898.40 2,737.82 3,966.31 6 9,550.00 5,884.63 2,542.15 3,929.89 7 9,900.00 5,898.47 2,197.61 3,971.61 Planned TD at 9900.00 812112018 1:56:46PM Page 3 COMPASS 5000.14 Build 85 V ConocoPhillips BA- j(ER ConocoPhillips Travelling Cylinder Report UGHES a GEcompany Company: ConocoPhillips (Alaska) Inc. -Kup2 Project Kuparuk River Unit Reference Site: Kuparuk 2G Pad Site Error. 0.00 usft Reference Well: 2G-06 Well Error. 0.00 usft Reference Wellbore 2G-061-1-02 Reference Design: 2G-06L1-02_Wp03 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well 2G-06 2G-06 @ 140.00usft (2G-06) 2G-06 @ 140.00usft (2G-06) True Minimum Curvature 1.00 sigma EDT 14 Alaska Production Offset Datum teference 2G-06L1-02_wp03 'iftertype: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference nterpolation Method: MD Interval 25.00usft Error Model: ISCWSA )epth Range: 8,300.00 to 9,900.00usft Scan Method: Tray. Cylinder North tesults Limited by: Maximum center -center distance of 1,176,00 usft Error Surface: Pedal Curve Survey Tool Program Date 8/21/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description 200.00 8,100.00 2G-06 (2G-06) SEEKER MS BHI Seeker multishot 8,100.00 8,300.00 2G-06L1_wp03(2G-06L1) MWD MWD- Standard 8,300.00 9,900.00 2G-06L1-02_wp03 (2G-06L1-02) MWD MWD - Standard 'asing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,900.00 6:038.47 2 3/8" 2.375 3.000 Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) 2L Pad 2L-328 - 2L-328 (Sierra) - 2L-328 Planned Out of range Kuparuk 2G Pad 2G-05 - 2G-05 - 2G-05 Out of range 2G-06 - 2G-06 - 2G-06 9,400.00 7.200.00 1,083.63 18.77 1,068.69 Pass - Major Risk 2G-06 - 2G-061-1 - 2G-06L1_wp03 9,400.00 7,200.00 1.083.63 4.88 1,082.59 Pass - Minor 1/10 2G-06- 2G-061-1-01 - 2G-06L1-01_wp05 9,400.00 7,200.00 1,083.63 4.96 1,082.59 Pass- Minor 1/10 2G-06 - 2G-061-1-03 - 2G-061-1-03_wp03 8,935.69 8,950.00 9.02 0.66 8.42 Pass - Minor 1110 Offset Design Kuparuk 2G Pad - 2G-06 - 2G-06 - 2G-06 Onset Site Error: 0.00 usft Survey Program: 200-SEEKER MS Rule Assigned: Major Risk Offset Well Error: 0.00 usft Reference offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toofface + Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/S +E/-W Hole Size Centre Distance Deviation (usftl (usft) (usft) (usft) (usft) (usft) (°) lam) (usft) on) (usft) (usft) (usft) 8,301.64 6,053.28 8.350.00 6.143.84 0.17 1.87 -131.11 3,414.91 3.783-80 3.000 91.34 8,54 84.07 Pass- Major Risk 8,315.27 6,054.82 8,375.00 6.164.02 0.18 2.05 -127.84 3,424.45 3,795.06 3.000 109.72 9.09 10111 Pass - Major Risk 8,327.88 6,055.84 8.400.00 6,184.20 0.18 2.24 -124.40 3,433.99 3,806,32 3.000 128.64 9.63 120.73 Pass - Major Risk 8,340.00 6,056.45 8,425.00 6,204.38 0.19 2.42 -120.83 3,443.53 3,817.57 3.000 148.05 10.16 139.87 Pass - Major Risk 8,350A6 6,056.67 8,450.00 6,224.56 0.19 2.61 -117.60 3.453.07 3,828.83 3.000 167.93 10.67 159.52 Pass - Major Risk 8,360.00 6,056.65 8,475.00 6,244.74 0.20 2.79 -114.37 3,462.61 3,840.09 3.000 188.23 11.18 179.61 Pass - Major Risk 8,363.60 6,056.58 8,485.00 6,252.81 0.20 2.87 -113.15 3,466.43 3,844.60 3.000 196.47 11.38 187.77 Pass - Major Risk 9.400.00 6,032.00 7.200.00 5,278.26 0.91 0.00 -121.00 2,923.40 3,211.16 3.000 1,083.63 18.77 1,068.69 Pass - Major Risk, CC, ES, SF 9,417.40 6,030.23 7,175.00 5,260.70 0.93 0.00 -122.24 2,911.85 3,197.63 3.000 1,102.43 19.01 1,087.27 Pass - Major Risk 9,424.08 6,029.61 7.150.00 5,243.19 0-95 0,00 -122.83 2,900.25 3.184.06 3.000 1,121.47 19.11 1,106.22 Pass - Major Risk 9,430.65 6.029,04 7,125.00 5.225.73 0.96 0.00 -123.40 2,888.61 3,170.47 3.000 1.140.62 19.21 1.125.28 Pass - Major Risk CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 812112018 4:11:01 PM Page 2 COMPASS 5000.14 Build 85 Hu >CN£a N c cs J� ifs L17 am O N O � O n O r � m m F- F- m O O Y N c QF-Cn W vin con d n o r r O N O N O O M 10 a 0 l0 Z v vNOO . � C-eC M M f h M N N N N 7 � CD O) N O O O O O O O O O CZO 0 0 0 0 0 0 0 0 0 6 6 c r L n c o O N c r) c 0 0 0 L[ O M( O CN A M N N m0 0 0 0 0 0 0 O G J O O O O O O O O ?) a O-%r 00 r 0 e- 0 0 O r M N r M 00 t 0 i y J O C Oi } O r M O M c O N r r e0 v- 0 0 0 0 O p j M M V V N J LLU> (n tOOrrON�� Q o Noo o?L�n0 co Z o 6 cn r� W Q + a 7NO�n�[Jzz M M M M N N N N J J (o t D L n M 0 0 0 M n W (nOOMnaO V c0 V' CN 0 V:4 Ni o Mm�OMi ..L-+�..� QfO a0M Wo000 ` c,� Ln � Ln V) Z — ";V 'N r M 0 V M N M M Q O Cl! r- r M O Cl! O L O O c Y r a 0 O N O N( R U�nl (O NOO V C MLnll�NM V M� O N 01 m m� M O ao O .00 .00 LLJO + p o 0 0 0 0 0 0 0 O o 0 0 0 0 0 0 0 0 Cl 0 0 0 Cl 0 00002 o M V A D O M� f] O �0 �,._.NMvin co rao zo o I (ui/)jsn 0s) tlidaQ [eoil►an aruj, KUP PROD 2G-06 ConocoPhillips r* �: Alaska, Inc. well Attributes jMaxAngIe&MD TD Field Name Wellbo , APINNA Wdibore KUPARUK RIVER UNIT 500292112100 PROD Status nel CI MD 4.60 4,000.00 (ftKB) Oct 8,485.0 Btm (tiKB) SS,Ve: ol SSSV: NIPPLE H2S (pp.) Date 111, 12/19/2017 Annotation Last WO: End Date 7/14/2010 KB-Grd A Rig 36.00 6/18/1984 Release Date 2G-06, 7/1712J18 903.32 AM Last Tag VMical schematic (actual) Annotation Last Tag: RKB End Data 7715/2 I, Depth (RKB) Las[ 8, 168.0 fergusp Mod By HANGER: 30J CONDUCTOR. 38.0-1100 1 NIPPLE: 524.7 GAS LIFT, 2.951.5 SURFACE, 37.2-3,133.9- GAS LIFT; 4,945.4 GAS LIFT; 6,250.3 GAS LIFT: 7,246.0 GAS LIFT: 7, 998.2 PER: 7,956.E PACKER. 7,968.3 NIPPLE; 8,011.2 FISH; 8,158.0 IPERF: 8,188.0A,198A- IPERF; 8,216.0412,16.0- PRODUCTION; 35.9-8.449.1 1 Last Rev Reason Annotation End Date Last Mod By Rev Reason: Set new Rockscreen. 7i16/2018 fergusp Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) Top 15.06 38.0 (RKB) Sec 110.0 Depth (RKB) Set 110.0 Depth (TVD)... WtILen 62.58 (L.. Grade H-40 Top Thread Welded Casing Description SURFACE OD (in) 95/8 ID (in) Top 9.21 37.2 (RKB) Set 3,133.9 Depth (RKB) Set 2,773.7 Depth (TVD)... Wt1Len 36.00 (I... Grade J-55 Top Thread BTC Casing Description PRODUCTION OD (in) 7 ID (in) Top 16.28 35.9 (RKB) Set 8,449.1 Depth (RKB) Set 6,223.8 Depth (TVD)... WHLen 26.00 (I... Grade J-55 Top Thread BTC Tubing Strings Tubing Description String Mo... ID (in) Top (RKB) Set Depth fft- Sat Depth fTVD) (... V (Ib/R) Grade Top Connection TUBING WO 31/2 2.99 30.1 7,969.3 5,841.4 9.30 L-80 EUE8rdABMOD Completion Details Top (RKB) TOP(TVDi (RKB) Top Intl (") Item Des Com Nominal ID (in) 30.1 30.1 0.09 HANGER Vetco/Gray Gen II TUBING HANGER 2.938 524.7 524.6 1.18 NIPPLE 3.5" CamCO'DS' Nipple w/ 2.876 profile 2.875 7,956.6 5,931.6 39.63 PER PBR Sea( Assembly (sheared) w/ 7 space out STABBED INTO PACKER ASSEMBLY 2.980 Tubing Description String Ma... ID (in) Top (RKB) Set D-.PSat Depth O VD) (... VA (ibfR) Grade Top Connection TUBING Packer Assy 3 112 2.99 7,968.3 8,( th (ft. 36 5,899.1 9.30 L-80 8RD EUE Completion Details Top (RKB) Top (TVD) Top (RKB) Incl (') Item Des Com Nominal ID (in) 7.968.3 5,840.7 39.50 I PACKER FHL Packer 3.030 8,011.2 5,873.8 39.03 I NIPPLE 2.813" DS Nipple 2.813 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (RKB) Top (TVD) Top (RKB) Intl A Des Com Run Date ID (in) 8,011.0 5,873.7 39.04 CS-LOCK/THEA ROCKSCREEN 2.81"CS-LOCK W/tapppered Rockscreen, 2.79 x 2.40"" THEA Rockscreen (OAL 80') 7116/2018 0.000 8,158.0 5,989.3 37.21 FISH LOWER PACKER FROM OLD COMPLETION, PXX PLUG, & REST OF TUBING DOWN TO WIRELINE RE - ENTRY GUIDE IS IN FILL. TAGGED HARD MUD aQ 8158 SLM. 1/6/2008 0.000 Perforations & Slots Top (RKB) Top Bum (RKB) (TVD) (RKB) Btm (TVD) (RKB) Linked Zone Date Shot Dens (shots/R ) Type corn 8,188.0 8,198.0 6,013.3 6,021.3 A-5, 2G-06 9/24/1988 4.0 IPERF 90 deg. Phasing; 4" Schlumberger Casi 8,216.0 8,246.0 6,035.7 6,059.9 A4, 2G-06 9/24/1988 4.0 IPERF 90 deg. Phasing; 4" Schlumberger Casi Mandrel Inserts St an N Top (ftKB) Top (TVD) (RKB) Make Model OD (In) Sm Valve Type Latch Type Port Size (in) TRO Run (Psp Run Date Com 2,951.5 2,655.4 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,240.0 2/8/2018 9:30 2 4,945.5 3,851.9 Camco MMG 1 i/2 GAS LIFT GLV RK 0.188 1,220.0 2/MO18 10:30 3 6,250.3 4,646.2 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,217.0 2/8/2018 1:00 4 7,246.0 5,310.6 Camco MMG 11/2 GAS LIFT GLV RK 0,188 1,232.0 2/8/2018 9:30 5 7,898.2 5,786.8 Camco MMG 1 1l'2 GAS LIFT OV RK 0.250 0.0 2/7/2018 10:30 Notes: General & Safety End Date Annotation 1/272000 NOTE: WORKOVER 1211012007 NOTE: "MIT TESTING WILL HAVE TO USE DS NIPPLE @ 8008' "' 12/10f2007 NOTE: WORKOVER 7/2/2009 NOTE: 5005 = TIGHT SPOT, UNABLE TO WORK 2.6" GAUGE RING PAST 6/27/2009 7/2/2009 NOTE: View Schematic w/ Alaska Schematic9.0 Q Q � � O o p �4� m Now jgao 0 clr:.a R m pv NOJ (y 'gyp NJ J � m irl `m O .J O M) co Nt fV M LO U ; pN� N v V M Q 00 V I 1i /i 11 0 Im in a N N tu rn N c+i i M n m ih n' a 0 W Q flco L o c goo Co -e c — 0o a m a m J C o U fco — N C cl E a J fA f0 C � = f1! 7 W Q V f0 c7 11 Q N N N (p a Ad N N � r � N mf6 l l Cl) m M P� M M m c�) i� , I � I I 0 L Q N ui Q g g g N u )co Nzo N o "v �p� n v v � C2 �J a W aN n co Ncn a c oao za co c 21 m Y 1 �. '- ND �= Qdo Qallo c0 C) N 41 TRANSMITTAL LETTER CHECKLIST WELL NAME: K R (,C, a (;- 06 1/Development Service _ Exploratory Stratigraphic Test _ Non -Conventional FIELD: Vu paya k R 1 Vel— POOL: K"na�y u k P% t Ve_j- O 1 L Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit No. I mac - -. p $Z API No. 50- o2q - z 1121 -_go -_. (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, ✓( composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 Well Name: KUPARUK RIV UNIT 2G-06L1-02 _ _ Program DEV Well bore seg ❑d PTD#: 2181140 Company CONOCOPHILLIP_S _ALASKA, INC. Initial Class/Type DEV / PEND GeoArea 890 Unit 11160 _ On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate_ Yes 3 Unique well name and number Yes 4 Well located in a defined pool Yes �5 Well located proper distance from drilling unit boundary Yes Conservation Order No. 432D has no interwell spacing restrictions. Wellbore will be more than 500' 6 Well located proper distance from other wells Yes from an external property line where ownership or landownership changes. As proposed, well will 7 Sufficient acreage available in drilling unit Yes conform to spacing requirements. 8 If deviated, is wellbore plat included No Directional plan view for 4 laterals is included. 9 Operator only affected party Yes 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order Yes 12 Permit can be issued without administrative approval Yes DLB 9/24/2018 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA i15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided NA Conductor set in KRU 2G-06 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 2G-06 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with uncemented slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations_ _ NA Appr Date 28 Drilling fluid program schematic _& equip list adequate Yes Max formation pressure is 4908 psig(15.5 ppg EMW); will drill_w/ 8.6 ppg EMW and maintain overbal_ w/ MPD VTL 10/5/2018 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 4320 psig; will test BOPs to 5000psig 31 Choke manifold complies w/API RP-53 (May 84) Yes I32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable Yes H2S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 2G-Pad are H2S-bearing. H2S measures required. Geology 36 Data presented on potential overpressure zones Yes Appr Date 37 Seismic analysis of shallow gas zones NA DLB 9/24/2018 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner _ Date i
